Apparatus and Method for Lateral Well Drilling

ABSTRACT

A downhole tool assembly for cutting laterally into an earthen formation from a wellbore. The downhole tool assembly includes a cutting head assembly and a flexible tubular shaft member, wherein the cutting head assembly includes a rotatable nozzle and a cutting head sized and configured to cut laterally into the earthen formation.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority to U.S. Provisional Application No. 61/402,799 and U.S. Provisional Application No. 61/402,803, both filed on Sep. 7, 2010.

FIELD

The present invention relates to an apparatus and method for cutting wellbore components and/or earthen formation surrounding the wellbore. More specifically, the invention relates to an apparatus and method for mechanically cutting earthen formation surrounding the wellbore, and optionally, casing and/or cement disposed in the wellbore, through the use of a rotatable, mechanical cutting head assembly.

BACKGROUND

A multitude of wells have been drilled into earth strata for the extraction of oil, gas, and other material there from. In many cases, such wells are found to be initially unproductive, or may decrease in productivity over time, even though it is believed that the surrounding strata still contains extractable oil, gas, water or other material. Such wells are typically vertically extending holes including a casing usually of a mild steel pipe having an inner diameter of from just a few inches to over eight inches used for the transportation of the oil, gas, or other material upwardly to the earth's surface. In other instances, the wellbore may be uncased at the zone of interest, commonly referred to as an “openhole” completion.

In an attempt to obtain production from unproductive wells and increase production in under producing wells, methods and devices for forming a hole in a well casing, if present, and forming a lateral passage there from into the surrounding earth strata are known. For example, a hole in cased wells can be produced by punching a hole in the casing, abrasively cutting a hole in the casing, milling a hole in the casing wall or milling out a vertical section of casing. While more or less efficacious, such methods are generally familiar to those in the art. In openhole wells, the steps to form a hole in the casing are not required, but the methods for forming a lateral passage into the surrounding strata may be virtually identical to those used on cased well.

Under both the cased and uncased well scenarios, a type of whipstock is typically incorporated to direct the cutting head out of the wellbore and into the formation. The whipstock may be set on the end of production tubing. Because of the time and economic benefits, often the cutting tools are run on the end of coiled tubing. In at least one known conventional horizontal drilling method using coiled tubing, the cutting tool completes its transition to the horizontal direction over a radius of at least several feet and some methods require a radius of over 100 feet. The size of the radius stems primarily from the length and diameter of the cutting tools and the rigidity of the toolstring that must transition around the radius. Other known methods for creating horizontal drainage tunnels are able to transition a much tighter radius (e.g. within 4.5″ casing) by not attempting to pass relatively long and/or large diameter tools (e.g. a mud motor) outside of the wellbore. Instead most such methods utilize a flexible jetting hose with a specialized and relatively small nozzle head (e.g., less than a few inches long). Such methods may be efficacious, but typically suffer from a common problem that that they do not and/or cannot provide adequate torque to satisfactorily power a mechanical cutting means capable of cutting harder formation. Accordingly, these methods may be limited only to very soft formations.

Furthermore, most known methods and apparatus have also generally been unable to provide technically or commercially satisfactory results because of an accumulation of cuttings in the wellbore. Many known apparatus utilizing a form of jetting nozzles have been found unable to produce a satisfactorily large hole in the strata and, even when directed at soft strata, have been found to hang-up when trying to advance the nozzle into the formation.

In addition to the aforementioned, cuttings created from the lateral drilling process or materials in the wellbore can also be problematic. If the rat-hole of the wellbore (the portion beneath the work area) is not deep enough to accommodate these materials, the materials can fill the wellbore up to or above the elevation of the whipstock. This in turn, can effectively preclude the removal of cuttings from the lateral borehole being drilled as the cutting have nowhere to fall and hence cause a stop in forward cutting of the lateral borehole. Additionally, cuttings in the wellbore can fill-up so that repositioning of the whipstock, such as to a new zone of interest, movement of the whipstock cannot be done.

In view of the above, it would be desirable to have a cutting tool capable of being run on a wireline unit, on coil tubing or on jointed tubing or rod, the tool being capable of being run in a wellbore and capable of transitioning in a radius of less than about 36 inches to a substantially horizontal orientation, wherein the cutting tool is provided with sufficient torque to cut even hard formation, like dolomite. It would further be desirable to have a cutting system capable of rotating under the power of fluid and wherein the fluid may be emitted from the cutting tool to provide assistance in the removal of cuttings, to clean the cutting faces and/or to cool the cutting tool.

SUMMARY

An embodiment of the present invention is an apparatus for cutting laterally into an earthen formation from a wellbore that includes a flexible tubular member formed from a series of interconnectable drive segments, wherein the interconnectable drive segments collectively form at least one tubular member inner passageway. The flexible tubular member is sized and configurable such that an attached cutting head assembly, the tubular member inner passageway, and a fluid pumping source may be in fluid communication. Wherein a first flexible tubular member end portion is sized and configured to be attachable to a rotation means and a second flexible tubular member end portion operatively coupled to the cutting head assembly such that torque applied to the first flexible tubular member end portion by the rotational source may be translated to the cutting head assembly.

The cutting head assembly can have at least one cutting surface sized and be configured to mechanically cut into the earthen formation. The cutting head assembly can have at least one orifice for the ejection of fluid, gas or combination thereof positioned on or near the cutting head assembly and is capable of being in fluid communication with the fluid pumping source. The cutting head assembly can also have a centering member sized and configured to retain the cutting head assembly substantially longitudinal about the axis of a substantially horizontal wellbore created by the apparatus when engaged in cutting laterally into the earthen formation and the cuttings from the earthen formation may travel past the centralizing mechanism toward the wellbore.

There can be flutes or grooves on the drive segments that can facilitate the removal of cuttings. There can be one or more secondary tubular member disposed within the flexible tubular member inner passageway and capable of providing a substantially leak-proof fluid conduit between the pumping source and the cutting head assembly. There can be a flexible sealing material positioned between the interconnectable drive segments for the creation of a substantially leak-proof fluid passageway within the flexible tubular member inner passageway so as to establish a fluid conduit between the pumping source and the cutting head assembly. The substantially leak-proof fluid conduit can be created by utilizing an elastomeric material, hose, braided-hose, flexible tubing, KEVLAR®, tubing, convoluted tubing, interlocking hose or semi-rigid tubing, or combinations thereof.

The apparatus can include two or more interconnectable drive segments each having a base plane situated generally perpendicular to an axis of rotation and having at least two male teeth generally positioned on at least one sides of the base plan and having at least two female sockets generally positioned on the opposing side of the base plane, such that the at least two male teeth on one side of the base plane of an interconnectable drive segment can mesh into at least two mating female sockets on an adjacent interconnectable drive segment thereby permitting the articulation and transference of torque of the flexible tubular shaft member around a radius. In an embodiment the interconnectable drive segments can have both male teeth and female sockets on each side of the base plane.

The two or more interconnectable drive segments can have an outer profile that is generally cylindrical or barrel-shaped. In an embodiment the two or more interconnectable drive segments can have a base plane situated generally perpendicular to an axis of rotation and have at least one male drive tooth generally situated on one side of the base plan and at least one mating female socket on an opposing side wherein two or more lines bounding an edge of the male tooth do not meet at a single point on one side of the base plane, even if said lines bounding the edge(s) are extended.

In an embodiment the apparatus is capable of emitting fluid from the orifice on the nozzle providing benefits such as keeping the cutting head clean, keeping the cutting head cool, emitting fluid to better dispose the formation to be cut, emitting chemicals for treating the formation, or emitting fluid to provide a medium for carrying formation cuttings back toward the wellbore. The flexible tubular member can be deployed within a wellbore by means of production tubing, wireline, slickline unit, coiled tubing, and combinations thereof.

The apparatus can include a rotational source selected from a fluid-driven motor, an electrical motor, or some combination thereof. The apparatus can include a tensioning means to hold the interconnectable drive segments together. The tensioning system can be the placement of an elastomeric material between the interconnectable drive segments so as to hold them in tension, the placement of a preload on a hose running through an inner tubular passageway of the flexible tubular shaft member, the placement of a preload on a cable(s) running through an inner passageway of the flexible tubular shaft member, the incorporation of a spring situated above the interconnectable drive segments wherein the spring pushes the interconnectable drive segments together, directly, pulls the interconnectable drive segments together by pulling tension on a hose, wire or cable(s) running through an inner passageway of the interconnectable drive segments, and combinations thereof.

The apparatus can include a whipstock to guide the interconnectable drive segments. The whipstock can include a passageway through which formation cuttings can pass from the cutting head assembly to a location below the whipstock. The apparatus can include a sealing apparatus used in conjunction with a wireline unit allowing fluid communication with surface pumping equipment, said sealing apparatus providing a sealing mechanism between a fluid motor and a tubular extending to the surface through which fluid can be pumped. The sealing mechanism diverting flow from the surface pumping equipment through said tubular and into the fluid motor causing rotation of the motor and attached interconnectable drive segments and ultimately cutting head assembly, said motor connected to a wireline whereby the flexible tubular member may be lowered so as to create a lateral borehole in the earthen formation.

An embodiment of the present invention is an embodiment is a method for cutting laterally into an earthen formation from a wellbore utilizing the apparatus described above.

An embodiment of the present invention is an embodiment is a method for cutting laterally into an earthen formation from a wellbore by guiding a downhole tool assembly having a series of interconnectable drive segments, defining at least one inner passageway, through a channel defined by a guide assembly and positioning the downhole tool assembly so that the downhole tool assembly contacts a portion of the earthen formation to be laterally cut. The downhole tool assembly is coupled to a conduit, such that the conduit and downhole tool assembly are in fluid communication. The method further includes pumping one or more fluids through the conduit and into the downhole tool assembly, rotating a cutting head of the downhole assembly and cutting a borehole into the earthen formation with the cutting head in a direction lateral to the wellbore.

In the method the downhole tool assembly can be operatively connected to a rotational source and the rotational source is coupled to a conduit, such that the conduit, rotational source, and downhole tool assembly are in fluid communication. The method further can include activating the rotational source, wherein a torque is applied to the interconnected drive segments forming a flexible tubular member and translating the torque to a cutting head of the downhole tool assembly, wherein the torque causes the cutting head to rotate.

The rotational source can be activated by the fluid flow through the conduit into the rotational source. The interconnected drive segments collectively define a tubular member inner passageway, and the downhole tool assembly further includes a nozzle defining one or more openings in fluid communication with at least a portion of a secondary tubular member disposed within the tubular member fluid passageway, wherein the method further includes pumping one or more fluids through the secondary tubular member and emitting the pumped fluid from the nozzle openings, whereby the fluid contacts the cutting head.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 illustrates a cross-sectional view of an openhole completed wellbore containing a whipstock prior to the use of the whipstock in conjunction with an embodiment of the present invention.

FIG. 2 illustrates a cross-sectional view of a cased wellbore containing a whipstock, wherein an embodiment of the present invention is deployed in the wellbore and is disposed to cut a lateral borehole thru a predefined hole in wellbore casing.

FIG. 3 illustrates a cross-sectional view of a cased wellbore containing a whipstock, wherein an embodiment of the present invention is deployed in the wellbore, guided through a guide channel in the whipstock, and has created a lateral borehole through the casing and cement and is proceeding into the earthen formation of interest.

FIG. 4A illustrates a plan view of an interconnected drive segment consistent with an embodiment of the present invention and consisting of male teeth or pins and mating female sockets (not shown) on opposing sides of the drive segment. FIG. 4B illustrates a cross-sectional view of generally cylindrical interconnected drive segments of FIG. 4A consistent with an embodiment of the present invention and showing the male teeth and mating female sockets.

FIG. 4C illustrates a cross-sectional view of a series of interconnected drive segments positioned around the radius of whipstock and consisting of the configurations depicted in FIGS. 4A and 4B with optional secondary tubular member, in this case a hose, positioned inside one of the inner passageway of the drive segments and consistent with an embodiment of the present invention.

FIG. 5A illustrates plan view of an interconnected drive segment consistent with an embodiment of the present invention and, in this case, consisting of multiple male teeth and female sockets on each side of the drive segment (opposing side not shown). FIG. 5B illustrates a side view of a drive segment of FIG. 5A showing both male teeth and female sockets on each side of the drive segment and the overall barrel profile of the drive segment consistent with an embodiment of the present invention. FIG. 5C illustrates a side view of a series of interconnected drive segments of FIGS. 5A and 5B articulating around a radius, shown with optional secondary tubular member (in this case being corrugated tubing) consistent with an embodiment of the present invention.

FIG. 6A illustrates a frontal view of a rotatable cutting head assembly, showing the cutting blades and a nozzle positioned in a recess of the cutting head; fluid exiting the orifices on the nozzle is used to keep the cutting blades clean and cool. FIG. 6B illustrates a cross sectional view of the cutting head assembly connected to a series of drive segments used for the transmission of torque and which circumscribe a hose used for the transmission of fluid to the cutting head assembly.

FIG. 7 illustrates a frontal view of a rotatable cutting head assembly, showing the cutting blades, in this case diamond inserts and an exit orifice positioned in a recess of the cutting head; fluid exiting the orifices is used to keep the cutting blades clean and cool. FIG. 7B illustrates a cross sectional view of the cutting head assembly connected to a series of drive segments used for the transmission of torque; in this case, the drive segments have been used with an optional tensioning cable for holding the drive segments together while fluid communication in the system is established by elastomeric seals positioned between the drive segments.

FIG. 8 illustrates an embodiment of the present invention situated downhole and operated by a coiled tubing unit, wherein the coiled tubing unit is pumping fluid to drive a fluid motor used to rotate the flexible tubular shaft member consistent with an embodiment of the present invention.

FIG. 9 illustrates an embodiment of the present invention operated by means of a wireline unit in conjunction with pumping equipment, whereby fluid pumped into production tubing is diverted by a sealing mechanism into a downhole fluid motor and, subsequently, traverses the flexible tubular shaft member and exits at the cutting head.

FIG. 10 illustrates an embodiment of the present invention wherein a coiled tubing unit and downhole motor are used to operate the flexible tubular shaft member while an air compressor is used to remove cutting from below the whipstock, by circulating them out of the wellbore, consistent with an embodiment of the present invention.

DETAILED DESCRIPTION

In an aspect of the current invention, an apparatus for cutting laterally into an earthen formation from a wellbore is provided. As used herein, the term “lateral” or “laterally” refers to a borehole deviating from the wellbore and/or a direction deviating from the orientation of the longitudinal axis of the wellbore. The orientation of the longitudinal axis of the wellbore in at least one embodiment is vertical, wherein such a wellbore will be referred to as a vertical wellbore or substantially vertical wellbore. However, it should be understood that the orientation of the longitudinal axis of the wellbore may vary as the depth of the well increases, and/or specific formations are targeted. As used herein, the term “strata” refers to the subterranean formation also referred to as “earthen formation.” The term “earthen formation of interest” refers to the portion of earthen formation chosen by the operator for lateral drilling. Such earthen formation is typically chosen due to the properties of the formation relating to hydrocarbons.

The present invention relates to an apparatus, system, and method for cutting laterally into an earthen formation. Optionally, the apparatus may be used for cutting laterally into cement disposed within the wellbore. Optionally, the apparatus may be used for cutting laterally into the casing and cement disposed in the wellbore. Using the apparatus to cut laterally through the casing, cement, and earthen formation is advantageous in that the number of trips of downhole can be reduced significantly. The apparatus may be used in cased wellbores or openhole wellbores. Optionally, the apparatus may be used in wellbores wherein the one or more hole may have already been created through the casing and/or cement.

Generally, the apparatus will be run to a depth in the wellbore suitable for the retrieval of hydrocarbons and/or other desired materials. The location of the lateral boreholes will be operator specific and may vary based on the needs and goals of the operator. The location of the lateral boreholes may also be determined by the location of the wellbore and the environmental properties of the surrounding strata.

In at least one embodiment, the apparatus is a downhole tool assembly including a cutting head assembly and a flexible tubular shaft member attached to a means of rotation. When in use in a wellbore, the downhole tool assembly can be connected to a spool assembly including a conduit that can be used to lower the downhole tool assembly inside the wellbore. For example, the downhole tool assembly may be connected to a fluid motor and coil tubing that can be lowered into a wellbore and operated so as to cause rotation of the apparatus. In another embodiment, the downhole tool assembly is coupled to jointed tubing or pipe and a pumping source, whereby the downhole tool assembly is in fluid communication with pumping equipment by virtue of the jointed tubing string. In another embodiment, the downhole tool assembly is operatively connected to pumping equipment and a slickline or e-line unit, which together allow for placement, operation and/or retrieval of the downhole tool assembly. In an embodiment, the downhole tool assembly is operatively connected to pumping equipment and jointed rod which together can be used to control the operation of the downhole tool assembly.

One end portion, or first end portion, of a conduit or tubing run into the wellbore can be coupled to a fluid pumping source. Optionally, the second end portion of the conduit is coupled to the first end portion of the flexible tubular shaft member such that the fluid pumping source is in fluid communication with the flexible tubular shaft member. The fluid pumping source can be any conventional fluid pump capable of providing fluid pressures to the downhole tool assembly such that the downhole tool assembly is able to emit fluid from or near the cutting head. Optionally, the fluid may be emitted at a pressure from about 100 to 5000 psi. Optionally, the fluid may be pumped at a pressure from about 5,000 to about 15,000 psi. The flow rate of the fluid may range from about 4 to about 12 gallons per minute (gpm). In another embodiment, the operating flow ranges from about 10 to about 20 gpm. In a further embodiment, the operating flow ranges from about 15 to about 35 gpm. Nonlimiting examples of the fluid pumped from the fluid pumping source include nitrogen, air, foam, diesel, hydrochloric acid, water, formation brine, biocides, wettability agents, surfactants, and the like.

In an embodiment, the second end portion of the conduit is coupled to a rotational source in an embodiment of the present invention. In at least one embodiment, the rotational source can be a motor sized and configured to be run into the wellbore and capable of operating at the depth and conditions desired by the well operator. A nonlimiting example of such a motor is a mud motor, such as the 175RS640 manufactured by Roper Pumps. The motor can be operatively coupled to a first end portion of the flexible tubular shaft member, discussed further below. The motor can be coupled to the first end portion of the flexible tubular shaft member such that a torque generated by the motor is applied to the flexible tubular shaft member, thereby causing the flexible tubular shaft member to rotate consistent with the torque applied by the motor. The motor may be further configured such that the fluid pumping source may be in fluid communication with the first end portion of the flexible tubular shaft member, discussed more fully below. In another embodiment, the rotation source of the downhole toolstring may be a surfaced-based rotational source, such as a power swivel, which is used to rotate the downhole toolstring by virtue of rod or tubing connected to the downhole toolstring. In yet another embodiment, the rotational source connected to the downhole tool may be a DC motor, such as operated by an e-line unit.

Optionally, the downhole tools may include a vibration source. The vibration source may be sized and configured to impart vibrations to shake the cutting head assembly and/or flexible tubular shaft member to facilitate the removal of cuttings and allows the cutting head assembly to more effectively penetrate into and be retrieved from the earthen formation. Optionally, the vibration source may be attached to the flexible tubular shaft member or cutting head assembly. Optionally, the vibration source may be derived directly from the rotational source. The rotational source may further include a transmission, wherein the torque or revolutions per minute (rpms) of the rotational source may be adjustable.

As discussed above, the downhole tool assembly includes a flexible tubular shaft member in at least one embodiment of the present invention. The flexible tubular shaft member includes a first end portion discussed above and a second end portion wherein the second end portion can be coupled to the cutting head assembly. The flexible tubular shaft member may define at least one hollow tubular cavity, which may be referred to as a tubular member inner passageway. In at least one embodiment, a secondary tubular member defining an interior passageway (e.g. a hose) may be disposed within a tubular member inner passageway and further coupled to and in fluid communication with the cutting head assembly. In an embodiment used with a sealing mechanism, described in more detail below, the first end portion of the flexible tubular shaft member allows for internal to external porting whereby fluid can enter into the inside of the flexible tubular shaft member and optional secondary tubular member thereby allowing it to flow to the cutting head assembly. The first end portion of the flexible tubular shaft member may be operatively connected to a motor, whereby torque applied to the flexible tubular shaft member by the actuation of the motor may be translated to the cutting head assembly coupled to the second end portion of the flexible tubular shaft member. The cutting head assembly may rotate from the translated torque thereby cutting the earthen formation.

Optionally, the flexible tubular shaft member includes one or more centralizing members that can enable it to be centralized with respect to the wellbore and/or lateral borehole. Nonlimiting examples of centralizing members include radially oriented pins, brushes or springs.

In at least one embodiment, the downhole tool assembly may include an upper cross-over member connected to the first end of the flexible tubular shaft member. In at least one embodiment, the upper cross-over member has at least one passageway allowing for it to transmit fluid to the inside of the flexible tubular shaft member. In at least one embodiment, the upper cross-over member is coupled to a motor on the one side and to the flexible tubular shaft member on the other side, so as to allow for the transmission of torque to the flexible tubular shaft member. In at least one embodiment, the upper cross-over member can both transmit torque, such as by threading or splines, and allow for the transmission of fluid through a passageway. In at least one embodiment, the upper cross-over member can be used to help tension a tensioning system, described in more detail below, used to keep the drive segments engaged with one another. In at least one embodiment, the upper cross-over member utilizes a nut and/or spring to keep the flexible tubular shaft member's components engaged with one another. In at least one embodiment, the upper cross-over member can transmit torque, allow for the transmission of fluid, and be used to put tension on a tensioning system running within the flexible tubular shaft member.

In an embodiment, the flexible tubular shaft member comprises a series of drive segments capable of transitioning through and transmitting torque around a radius of less than 36 inches. The series of drive segments can be sized and configured such that each drive segment engages at least one other drive segment whereby torque is transmitted from drive segment to drive segment. In an embodiment, the drive segments transmit torque through one or more pins or teeth on a side of each drive segment and a respective mating socket on an adjacent drive segment. In one embodiment, each drive segment is configured with both a male tooth and a female socket on each side of the drive segment. In either of the aforementioned arrangements, each drive segment is configured with both male and female parts. In at least one embodiment, there are at least two male teeth and two female sockets on each side of the drive segments. In an embodiment there are four teeth and four sockets on each side of the drive segments. Each drive segment has at least one opening, collectively defining at least one inner tubular passageway. Optionally, the drive segments can be connected by one or more hoses or cables used to as a tensioning system to hold the drive segments together, as more fully discussed below. The flexible tubular shaft member comprising the drive segments are further sized and configured to transmit torque applied from the rotational source to the cutting head assembly such that the cutting head, discussed below, is supplied with sufficient torque to cut the intended earthen formation. Optionally, one or more drive segments defines at least one groove, spiral, or flute, wherein the groove, spiral, or flute may allow cuttings and/or fluid to be carried from the cutting head past the drive segment and toward the wellbore.

As noted above, each drive segment may define one or more drive segment openings, as a whole forming at least one tubular member inner passageway. Optionally, a secondary tubular member, such as flexible hose or tubing, may be disposed within the at least one tubular member inner passageway. Nonlimiting examples of the secondary tubular member are hose or braided hose, KEVLAR®, convoluted tubing, interlocking hose, semi-rigid tubing, and the like. The secondary tubular member is in fluid communication with the fluid pumping source and the cutting head assembly. In certain embodiments, the secondary tubular member sits in the center of the series of drive segments. Optionally, the secondary tubular member is disposed within the flexible tubular shaft member and is connected to and in fluid communication with the cutting head assembly. The secondary tubular member within the flexible tubular shaft member can be fed, or transitioned, through a whipstock and into the earthen formation with the flexible tubular shaft member. In certain embodiments, the secondary tubular member can be integral to or can circumscribe a tensioning system, discussed in more detail below. In an embodiment, the circumscribed secondary tubular member, the series of drive segments, the tensioning system, described below, and the cutting head are rotated simultaneously.

In certain embodiments wherein the flexible tubular shaft member can be used without a secondary tubular member, seals positioned at least in part between the interconnected drive segments can be used to produce fluid communication between the opposite ends of the flexible tubular shaft member. That is, in this fashion fluid communication can be established between the first end of the flexible tubular shaft member end and the second end of the flexible tubular shaft member end, without usage of a hose or similar continuous conduit. In this embodiment, a sealing mechanism, such as elastomeric seals bonded to adjacent interconnected drive segments, could allow for fluid to be pumped through the passageway within the flexible tubular shaft member.

In at least one embodiment, the drive segments are held in contact with one another by a tensioning system. The tensioning system may be comprised of one or more tensioning lines running from and affixed to the cutting head assembly on the one end and to an upper cross-over member, discussed below, on the other. Optionally, the tensioning line may be comprised of one or more hose(s) or cables(s). Non-limiting methods to put tension on the tensioning lines include affixing one end to the cutting head assembly, such as by a crimp or threaded connection and employing a tensioning mechanism on the other end. Optionally, the other end of the tensioning line may terminate in an upper cross over member, discussed below, wherein a tensioning mechanism, such as a crimp and adjustable nut, may be employed to set a predetermined amount tension on the tensioning line. Optionally, the tensioning line may connected to a spring, which can be preloaded and which may allow for varying amounts of tension to be placed on the tensioning line. Again, applying tension to the tensioning line will cause the drive segments to be held together since the opposing ends of the tensioning lines terminate beyond the opposing ends of the drive segments. Optionally, the tensioning line(s) may be situated around the axis of rotation of each drive segment (for example, at zero, 120 and 240 degrees) or it may be situated along the axis of rotation. In another embodiment, the tensioning line may lie inside the second tubular member situated inside the series of drive segments. In an embodiment, the tensioning lines may be situated about the exterior of the drive segments. An alternate embodiment also employs a tensioning line(s) affixed to the cutting head assembly on the one end and terminating at the upper cross over member on the other. In this embodiment, a spring in the upper cross over member may be used to push on the drive segments themselves thereby holding them together and wherein the pushing force terminates in the cutting head assembly by virtue of the tensioning line also terminating there. These and similar tensioning mechanism are intended to be within the scope of this application.

Embodiments of the present invention may include an upper cross over member, which may serve multiple purposes. As described above, it may serve as part of the tensioning system used to keep the drive segments of the flexible tubular shaft member engaged with one another. Additionally, the upper cross over member may allow for fluid communication to be established with the flexible tubular shaft member, whether by merely conveying fluid exiting a downhole motor into the flexible tubular shaft member or by diverting flow from the upset tubing by virtue of a sealing mechanism. Finally, the upper cross over member may provide a means of transferring torque from a rotational source to the flexible tubular shaft member, such as by splines or threading.

Optionally, an exterior surface of the flexible tubular shaft member defines one or more flutes, grooves or rifling, which can facilitate cuttings from the borehole to flow past the flexible tubular shaft member and up the wellbore.

In an embodiment, the cutting head assembly includes a cutting head, wherein the cutting head can be detachably attached to the cutting head assembly and further configured to be rotatable and to cut laterally through casing, cement, and/or earthen formation. Optionally, the cutting head assembly defines a cutting head sized and configured to cut laterally through casing, cement, and/or earthen formation. The cutting head can form one or more recesses within the cutting head assembly to allow for some or all of the following: to provide placement of the one or more exit orifices for the fluid flow, to allow for efficient cutting of the formation and/or to allow provide a passageway for cutting to be removed from the cutting head area. The cutting head includes one or more cutting surfaces or faces, and may be configured such that one or more orifices may be able to eject fluid, gas or a combination thereof near the cutting surface(s) or face(s). A cutting face may circumscribe a portion of a rotatable nozzle, or a plurality of cutting faces may collectively circumscribe a portion of a rotatable nozzle. The cutting head can be continuous or segmented (e.g. serrated). The cutting face(s) can be formed from a material of sufficient hardness for cutting the intended earthen formation and/or casing and cement. For example, at least a portion of the cutting face may be formed from carbide or diamond.

The cutting head can be defined by the cutting head assembly or fixedly attached or can be detachably attached to the cutting head assembly. A non-limiting example of a detachable attachment is conventional threading. In an embodiment, the cutting head is detachably attached to the cutting head assembly, wherein the cutting head assembly includes one or more bearings or the like to facilitate rotation of a rotatable nozzle. The bearing may be a mechanical bearing, such as a bronze bushing, needle bearing, or ball bearing. Optionally, the bearing may be a fluid bearing, wherein a fluid bearing may be created upon the pumping of a fluid into the flexible tubular shaft member and cutting head assembly. Optionally, the fluid and/or mechanical bearings may be used in conjunction with seals.

The cutting head assembly defines one or more head assembly openings in an embodiment of the present invention. The head assembly openings can be sized and configured to permit fluid flow there through. The cutting head assembly can include the secondary tubular member wherein the secondary tubular member defines one or more secondary tubular member openings sized and configured to permit fluid flow there through into a space or chamber located inside the rotatable nozzle, discussed below. The cutting face may define one or more cutting face openings and the interior face surface may define one or more cutting face openings, wherein the cutting face opening is in fluid communication with the fluid pumping source. The head assembly openings and/or secondary tubular member openings can be stationary with respect to the cutting head or can move independently of the cutting head. Fluid flow through the head assembly openings and/or secondary tubular member openings can be used to keep the cutting head cool, facilitate the removal of cuttings from the borehole, and/or impart rotation of the cutting head and/or rotatable nozzle.

Optionally, the cutting head assembly includes one or more centering members sized and configured to retain the cutting head assembly centrally located along the longitudinal axis of a borehole created by the apparatus when engaged in cutting laterally into the earthen formation. Non-limiting examples of suitable centering members include bow springs, brushes, pins, and fluids. The centering member also may function to allow cuttings and fluid or gases emitted from the cutting head assembly to readily pass the cutting head assembly and move toward the wellbore.

In an embodiment, the pressure of the fluid at the nozzle openings is greater than about 100 psi. In another embodiment, based on desired operator parameters and treatment protocol, the pump pressure may be from about 5,000 psi to about 12,000 psi. The fluid pumped through the nozzle openings may accomplish one or more of the following: keeping the cutting head cool for cutting face longevity, keeping the cutting faces clean for efficient formation drilling, providing a carrying medium for transporting of cutting toward the wellbore, ejecting chemicals used to better dispose the formation to mechanical cutting, or to inject a chemical (e.g. biocides, inhibitors, wettability modifiers, etc.) to treat the formation adjacent to the lateral borehole.

As stated above, the cutting head assembly can be connected to the second end portion of the flexible tubular shaft member, wherein a motor can be connected to the first end portion of the flexible tubular shaft member, such that the flexible tubular shaft member is rotatable when the motor is engaged. In an embodiment, the motor can be driven by the flow of fluid from the conduit, thereby causing the flexible tubular shaft member to rotate, wherein at least a portion of the fluid used to drive the motor is transmitted inside the flexible tubular shaft member to the cutting head assembly and/or nozzle. Optionally, the motor may be driven by the flow of fluid from the conduit, thereby causing the flexible tubular shaft member to rotate and fluid from the fluid pumping source is pumped through the secondary tubular member to the cutting head assembly in order to drive the rotatable nozzle and/or cutting head.

In an embodiment, the cutting head assembly may comprise a specialty nozzle head, such as a rotating nozzle, a pulsing nozzle, a nozzle that creates a swirling pattern in its discharge flow, a nozzle designed to produce cavitation. Such a nozzle maybe necessary or desirable to more effectively clean the cutting head to facilitate the return of cuttings back to the wellbore and/or for marketing purposes.

In an embodiment, the fluid leaving the nozzle opening(s) on the cutting head can generate the rotation of a rotatable nozzle, such as through an exit orifice asymmetrically oriented with respect to the axis of rotation of the nozzle. Optionally, a rotatable shaft contained in a mating body may be connected to the rotatable nozzle to provide stabilization and a consistent axis of rotation for that nozzle. Optionally, the rotatable nozzle and/or attached rotatable shaft may comprise a fluid bearing with the mating body. In yet another embodiment, in the presence of flowing fluid, the configuration of the cutting head assembly may be used to create a swirling or pulsing pattern in the fluid flow, thereby causing rotation of the shaft connected to the rotatable nozzle and, thus, the connected rotatable nozzle. At least a portion of the rotatable nozzle can be disposed within a recess formed by the cutting head. In at least one embodiment, the rotatable nozzle is positioned toward the center of the recess formed by the cutting head.

In an embodiment, the cutting head assembly further includes a rotatable nozzle defining one or more nozzle openings. At least a portion of the rotatable nozzle can be disposed within a recess formed by the cutting head. In at least one embodiment, the rotatable nozzle is positioned toward the center of the recess formed by the cutting head. The nozzle openings can be defined in a symmetric or asymmetric pattern by the rotatable nozzle. The nozzle openings are sized and configured such that fluid pumped from the fluid pumping source through the conduit and flexible tubular shaft member can be emitted from the nozzle openings with the desired pressure selected by the operator.

As discussed above, in at least one embodiment, the cutting head forms a recess wherein at least a portion of the rotatable nozzle is disposed within. In an alternate embodiment, the cutting head forms a recess wherein the rotatable nozzle is disposed substantially within the recess. In at least one embodiment, the fluid exiting the nozzle(s) can flow to the outside of the cutting head.

Turning now to a system and method for cutting laterally into an earthen formation from a wellbore, a whipstock is employed in at least one embodiment of the present invention. As used herein, the term “whipstock” refers to any downhole device capable of positioning the cutting head assembly toward the earthen formation desired for lateral cutting. The whipstock defines a guide channel sized and configured to receive and guide the cutting head assembly and at least a portion of the flexible tubular shaft member through the whipstock and proximate the earthen formation of interest. In at least one embodiment, the whipstock may guide the cutting head assembly into a substantially horizontal direction from a vertical wellbore such that the cutting head assembly is disposed approximately 90 degrees from the longitudinal axis of the wellbore. The whipstock may be disposed in the casing prior to the running of the downhole tool assembly. Optionally, the whipstock may be set with a coil tubing unit, on the end of production tubing or it may be set by a wireline unit. The whipstock may have one or more passageways running through it that allow cuttings from the lateral borehole to fall toward the bottom of the wellbore.

Optionally, the flexible tubular shaft member may comprise a section that is adaptable to the whipstock and forms a seal with the whipstock. This seal may restrict the backflow of fluid and materials up the whipstock so as to seal out any cuttings washing back from the lateral borehole. This may be desirable in order to prevent cuttings from clogging the guide path of the whipstock, which could inhibit the free travel of the flexible tubular shaft member.

Optionally, the guide assembly may have one or more passageways extending from the guide path to below the whipstock to allow cuttings to freely fall toward the bottom of the wellbore.

Optionally, the bottom hole assembly may define one or more circulation passageways traversing from above the whipstock to below the whipstock, allowing for cleanout of the wellbore. In an embodiment, the circulation pathway(s) may extend around the whipstock, connecting to the upset tubing on the one end and to a passageway through the center of a packer on the other end. In another embodiment, they extend through the bottom of the whipstock and also serve to as the passageway(s) used to allow cuttings to freely fall from the guide path toward the bottom of the wellbore. The passageway(s) may serve as a circulation path for fluid that is circulated through the wellbore for the removal of cuttings, sand, paraffin and other materials that may have accumulated in the wellbore below the whipstock. For example, it may be necessary to remove cuttings from below the whipstock in order to allow the bottom hole assembly to be repositioned to a lower zone of interest for the creation of another lateral. Additionally, cleaning out any cutting in the wellbore maybe necessary for the proper operation of the packer. In an embodiment, the circulation opening(s) extend around the whipstock to a location at the end of the bottom hole assembly located 5 feet below the whipstock. Pumping of fluid to circulate the wellbore through these opening(s) may be done initially, periodically or continuously. In an embodiment, maximum circulation velocity is attained by retracting the downhole tool string into the primary wellbore (e.g. into the upset tubing). In this fashion, unobstructed flow through the circulation passageway(s) is best created, allowing for optimal wellbore cleanout. Cleaning out the wellbore and unloading the well may be accomplished by pumping fluid or gas at sufficiently high pressure and volumes through one or more of the circulation passageways.

Optionally, the system may be used with a form of containment system for the flexible tubular shaft member. This system may be comprised of a series of collapsible cups, stackable centralizers or sheathing. The purpose for this system is to allow for the efficient transference of weight from the top of the flexible tubular shaft member to the bottom of the flexible tubular shaft member by preventing the flexible tubular shaft member from forming a helical path or buckling when weight is applied to it from above.

The flexible tubular shaft member connected to the cutting head assembly can be fed, or transitioned, through a whipstock, such that the cutting head of the cutting head assembly is positioned proximate the earthen formation of interest for lateral cutting. Optionally, the cutting head is positioned proximate the portion of the casing and/or cement proximate the earthen formation of interest for lateral cutting. In an embodiment, the motor coupled to the first end portion of the flexible tubular shaft member is actuated, whereby torque is generated by the motor and applied to the flexible tubular shaft member. The tubular member is sized and configured such that torque applied to the first end portion of the flexible tubular shaft member can be translated to the cutting head assembly coupled to the second end portion of the flexible tubular shaft member. The cutting head of the cutting head assembly rotates from the torque applied to the cutting head assembly and, in turn, the cutting faces contact the earthen formation, thereby cutting into the formation. Optionally, the cutting faces contact the casing and/or cement in wellbore environments wherein openings have not been pre-drilled in the casing and/or cement proximate the earthen formation of interest.

Optionally, a nitrogen generator at the surface may be provided and used in conjunction with a closed loop system to clean out cuttings from the lateral borehole and/or wellbore. Optionally, pumping pressure and volumes may be sufficiently high so as to allow the nitrogen and cuttings to be lifted back up the wellbore; the nitrogen may then be circulated back to the generator, and the process may be repeated. Optionally, the nitrogen may be pumped through a downhole motor and to the cutting head. This closed loop nitrogen system is cost beneficial since a smaller system may be used and the need for a fluid pump including liquids may be eliminated.

In an embodiment, a wellbore including a whipstock set at the desired depth in the wellbore is equipped with a fluid pumping source and a coil tubing unit including a spool of coil tubing, wherein a first end portion of the coil tubing is coupled to the fluid pumping source, and the second end portion of the coil tubing is coupled to a rotational source. The rotational source can be a motor as discussed above. The motor in this embodiment is attached to a downhole tool assembly including a cutting head assembly and a flexible tubular shaft member, wherein the fluid pumping source, coil tubing, flexible tubular shaft member, and cutting head assembly are in fluid communication. Optionally, at least a portion of a secondary tubular member is disposed within the flexible tubular shaft member and the secondary tubular member is in fluid communication with the fluid pumping source and the cutting head assembly. The coil tubing including the coupled motor and downhole tool assembly are lowered into the wellbore wherein at least a portion of the downhole tool assembly contacts the whipstock and is guided into the guide channel and positioned proximate the earthen formation of interest.

Optionally, the second end portion of the coil tubing is coupled to the downhole tool assembly such that the coil tubing is in fluid communication with the downhole tool assembly. The fluid pumping source can be coupled to the first end portion of the coil tubing in this embodiment. The coil tubing coupled to the downhole tool assembly is lowered into the wellbore wherein at least a portion of the downhole tool assembly contacts the whipstock and is guided into the guide channel and positioned proximate the earthen formation of interest.

Having described many of the apparatus of the present disclosure, let us further discuss the methods by which they system may be conveyed through the pre-positioned whipstock:

In an embodiment wherein a whipstock is disposed in a wellbore, a coiled tubing and pumping equipment can be connected to the upper end of the flexible tubular shaft member such that fluid pumped through the coiled tubing can drive a fluid motor and the attached flexible tubular shaft member and cutting head assembly. Now under rotation, the flexible tubular shaft member and attached cutting head can be directed out of the wellbore by the pre-positioned whipstock in order to cut a lateral borehole in the surrounding earthen formation. Optionally, the flexible tubular shaft member and attached cutting head may be used to through the casing and cement, if present, and proceed to cut into the surrounding earthen formation.

In an embodiment, wherein a whipstock is disposed in a wellbore and is coupled to a section of upset tubing, a slickline unit, such as familiar to those in the industry, can be used to position and control the travel of the downhole tool assembly. In this embodiment, a fluid driven motor is connected to the end of the slickline string on the one end and the flexible tubular shaft member and attached cutting head on the other end. The system can include one or more elastomeric sealing mechanisms positioned on or above the motor; the elastomeric mechanisms forming a relatively complete seal with the upset tubing. The sealing mechanism diverts fluid flowing through the upset tubing into the fluid motor, thereby causing the motor and attached flexible tubing member to rotate. Now rotating, the toolstring can be lowered so as to allow the cutting head to cut into the formation

In an embodiment wherein a whipstock is disposed in a wellbore, a wireline unit, such as familiar to those in the industry, can be used to position and control the travel of the downhole tool assembly. In this embodiment, an electrically driven motor is connected to the end of the wireline on the one end and to the flexible tubular shaft member and attached cutting head assembly on the other. This system can include one or more elastomeric sealing mechanisms positioned on or above the motor; the elastomeric mechanisms forming a relatively complete seal with optional upset tubing. The sealing mechanism diverts fluid flowing through the upset tubing into the flexible tubular shaft member and to the cutting head. Now rotating, the tool string can be lowered so as to allow the cutting head to cut into the formation.

In an embodiment wherein a whipstock is disposed in the cased wellbore and a wireline unit, such as familiar to those in the industry, can be used to position and control the travel of the downhole tool assembly. In this embodiment, an electrically driven motor is connected to the end of the wireline on the one end and to the flexible tubular shaft member and attached cutting head assembly on the other. This system can include one or more elastomeric sealing mechanisms positioned on or above the motor; the elastomeric mechanisms forming a relatively complete seal with optional upset tubing. The sealing mechanism diverts fluid flowing through the upset tubing into the flexible tubular shaft member and to the cutting head. Now rotating, the tool string can be lowered so as to allow the cutting head to cut into the formation.

In an embodiment a pumping equipment and jointed tubing, positioned by drilling or work-over equipment, can be connected to the upper end of the flexible tubular shaft member such that fluid pumped through the jointed tubing can drive a fluid motor and the attached flexible tubular shaft member and cutting head assembly. Now under rotation, the flexible tubular shaft member and attached cutting head can be directed out of the wellbore by the pre-positioned whipstock in order to cut a lateral borehole in the surrounding earthen formation. Optionally, the flexible tubular shaft member and attached cutting head may be used to through the casing and cement, if present, and proceed to cut into the surrounding earthen formation.

Turning now to the Figures, FIG. 1 illustrates an open hole completed wellbore (10) containing an orienting device (12), illustrated as a whipstock, coupled to a section of upset tubing (14). The whipstock (12) defines a guide channel (16) sized and configured to guide at least a portion of the flexible tubular member (not shown) of this disclosure to a position proximate the earthen formation of interest (20). The wellbore (10) includes a layer of cement (22) disposed between the casing (24) and earthen formation (20). An incline (26) is situated above the orienting device (12) to guide tools (not shown) into the guide channel (16). A circulation passageway (13) extending around the orienting device (12) formed, in this case, by a tubular member (9) in fluid communication with the upset tubing (14) at an upper entrance opening (7) and with the wellbore (10) at a lower exit opening (8) situated below the orienting device (12).

Looking now at FIG. 2, illustrated is a portion of the downhole tool assembly (18) that has been guided through the guide channel (16) defined by a whipstock (12) positioned on a packer (28). The cutting head (46) of the downhole tool assembly (18) is disposed in a pre-defined opening (31) in a portion of the casing (24) proximate the cement (22) and earthen formation (20). The first end portion (38) of the flexible tubular shaft (36) is operatively coupled to a rotational source (40) while the second end portion (34) of the flexible tubular shaft (36) is connected to a cutting head assembly (32). When activated, the motor (40) applies torque to the flexible tubular shaft (36), which has been sized and configured to transfer the torque to the cutting head assembly (32), thereby enabling cutting of the cement (22) and earthen formation (20).

FIG. 3 illustrates a downhole tool assembly (18) consistent with an embodiment of the present invention including a flexible tubular shaft member (36) comprising a series of drive disks (42), wherein a first end portion of the flexible tubular member (38) is coupled to an upper cross over member (90) in turn coupled to a motor (40) shown disposed in upset tubing (14) and the second end portion of the flexible tubular member (34) is situated in a lateral borehole (50) and connected to a cutting head assembly (32). The orienting device (12) is shown with optional lower passageway (3) in communication with the guide channel (16) and allows for any cuttings (C) in the orienting device (12) to fall through a passageway (29) in the packer (28) As shown, the cutting head assembly (46) has been used to cut a hole (30) through the casing (24) and cement (22) and is beginning to form a lateral borehole (50) thru the earthen formation (20). Fluid (F) pumped from a fluid pumping source (not shown) down a conduit (76) engages the motor (40) and imparts rotation of the flexible tubular member (36) and attached cutting head assembly (32). The fluid (F), shown by arrows, exits the motor (40) passes thru an upper cross over member (90) and into an optional secondary tubular member (66), shown here as a hose. The fluid (F), shown by arrows, exits the secondary tubular member (66) traverses thru a passageway (58) in the cutting head assembly (32) and exits at orifices (49).

FIGS. 4A illustrates an embodiment of a drive disk (42 a) of the flexible tubular member (not shown in full). The drive disk (42 a) defines a plurality of male teeth (82) and a plurality of inner passageways (78 and 37), illustrated here as four openings, sized and configured such that three tensioning cables (80) and a hose (69) may be inserted through the respective openings on the drive disk (42 a). FIG. 4B shows a plan view of the drive segment (42) in FIG. 4A. Evident in the figure are the teeth (82) and female sockets (84) of a drive segment (42). In this case, the overall profile of the drive segment (42) is cylindrical in shape (as shown by dotted lines). The inner passageway (37) and circumscribed hose (69) are shown; however, in this view and for purposes of clarity, the tensioning cables and their holes are not shown.

FIG. 4B shows a cross-sectional view of the drive disk (42 a) in FIG. 4A wherein the teeth (82) and female sockets (84) are evident, as is the inner passageway (37) containing the hose (69). In this case, the overall profile of the drive disk (42 a) is cylindrical in shape (as shown by outer set of dotted lines). Note: for purposes of clarity, the cables, which run parallel to hose (69) are not shown in this view. The teeth (82) on the drive disk (42 a) are used to drive rotation of the adjacent drive disk (not shown) while the hose (69) allows for fluid communication through the series of drive disks (not all shown).

FIG. 4C, shows an alternate version of a flexible tubular shaft member (36) in a radius (11) of a whipstock (not shown in full). The series of drive disks (42) of the flexible tubular shaft member (36) are similar to those depicted in FIGS. 4A and 4B. Evident is the hose (69), which serves as a secondary tubular member, and which run through the tubular member inner passageway (37) of the flexible tubular shaft member (36) and serves to help keep the individual disks (42 a, 42 b, 42 c etc.) held together. The series of drive disks (42) transmit torque generated from a motor (not shown) through the teeth (82) and respective mating sockets (84) on an adjacent drive disk (42), in this fashion torque may be transmitted from drive disk to drive disk. In this configuration, the plurality of the drive disks (42) are configured to each have one male side (83) and one female side (85). Tension on the drive series of disks (42) is enabled through the tensioning cables (80), as discussed more fully, below.

FIG. 5A shows an alternate embodiment of an individual drive disk (42 a) having an inner passageway (37) and five male teeth (82) and five female sockets (84) on both sides (opposing side not shown) for transmission of torque. In this figure, no separate passageway for the tensioning system is shown, however, one will notice a slightly wider diameter (45) beyond that of the teeth (82) due to the barrel shaped nature of the drive disk (42 a); this barrel profile is better evident in FIG. 5B.

FIG. 5B is a plan view of the FIG. 5A wherein male teeth (82) and female sockets (84) are evident on both sides of the drive disk (42 a). The teeth (82) and sockets (84) have radius breaks (86) to allow for easier meshing of the teeth (82) into their respective mating sockets (not shown) of the adjacent drive disk (not shown). Additionally, it is evident that the profile of the drive disk (42) has a barrel-shaped profile, as shown by the dotted lines.

FIG. 5C shows a radius (11) of a whipstock (not shown in full) containing a partial flexible tubular shaft member (36) comprised, in part, of a series of drive disks (42) like those depicted in FIGS. 5A and 5B. The teeth (82 a) of a drive disk (42 a) can be seen to mate into a respective female socket (84 b) on an adjacent drive disk (42 b), thereby allowing for the transmission of torque. In this embodiment, the inner tubular passageway (37) of the series of drive disk (42) is shown with a corrugated hose (89) serving as the means to provide fluid communication through the flexible tubular shaft member (36).

FIG. 6A illustrates a frontal view of a cutting head assembly (32) consistent with an embodiment of the present invention. Evident on the cutting head assembly (32) are the cutting faces (48) and the rotating nozzle head (52) with exit orifices (49) situated in a recess open to the exterior (54) of the cutting head assembly (32). In this depiction, rotation of the cutting head assembly (32) is counterclockwise, as shown by arrow. Fluid (F) exiting the exit orifices (49) can clean the cutting faces (48) and flow to the outside of the cutting head assembly (32), as shown by curved arrows.

FIG. 6B illustrates a cutting head assembly (32) and a partial flexible tubular shaft member (36) consistent with an embodiment of the present invention. A connection fitting (47) ties the hose (69) to the cutting head (46). The connection fitting (47) has passageway (51) to enable fluid communication between the hose (69) and exit orifices (49) on the cutting head assembly (32). In conjunction with the connection fitting (47), tension pulled on the hose (69) in the direction of the arrow (T) may serve to keep the series of drive disks (42) held together. The cutting head assembly (32) includes a nozzle head (53) disposed within a recess open to the exterior (54) of the cutting head assembly (32). The cutting head assembly (32) has a centralizing mechanism (62), shown as pins. The nozzle head (53) is in fluid communication with the hose (69) and exit orifices (49) by interior nozzle passageway (58). Fluid (F) exits (as shown by arrows) the nozzle head (53) to keep the cutting faces (48) clean and cool. The cutting faces (48) are shown with optional carbide inserts (150) for improved cutting of the earthen formation (not shown).

FIG. 7A illustrates a frontal view of a cutting head assembly (32) consistent with an embodiment of the present invention. Evident on the cutting head assembly (32) are diamond inserts (151) for improved cutting of the earthen formation (not shown) with cutting faces (48) an exit orifices (49). As shown by arrow indicating direction of rotation, behind the cutting faces (48) are back support areas (63) which provide structural support to the cutting faces (48) so as to resist breakage of the cutting faces (48) when cutting earthen formation (not shown).

FIG. 7B shows a lateral borehole (50) in an earthen formation (20) containing an embodiment of the flexible tubular shaft member (36) composed of a series of drive disks (42) coupled to a cutting head assembly (32) having diamond inserts (151) on its cutting faces (48) (only visible on 1 side). In this case, the inner passageway (37) of the flexible tubular shaft member (36) contains elastomeric material (71) spanning between the drive disks (42) and the cutting head assembly (32) to form seals. Fluid (F) in the flexible tubular member inner passageway (37) traverses through the cutting head assembly (32) thru passageway (61) in a connector (130) secured to a tensioning cable (122) and cutting head (46); the fluid (F) traverses passageways (58) and exits the cutting head (32) at orifices (49) so as to keep the cutting faces (48) clean and cool. The tensioning cable (122) runs through the flexible tubular member inner passageway (37) and terminates at a connector (130) located in the cutting head assembly (32). By pulling on the tensioning cable (122), in the direction shown by arrow (T), one is able to keep the series of drive disks (42) engaged with one another.

FIG. 8 illustrates a cross sectional view of an embodiment of the present invention wherein a whipstock (12) with guiding plane (26) is positioned on upset tubing (14) in a wellbore (10) surrounded by earthen formation (20). The illustration shows the downhole tool assembly (18) being operated by a coiled tubing unit (97) and pumping equipment (96), used to pump fluid (not shown) down the conduit (76), in this case coiled tubing, to the motor (40) so as rotate the flexible tubular shaft member (36) and attached cutting head (32).

FIG. 9 illustrates a wireline unit (95) and pumping equipment (96) positioned on a wellbore (10) in an embodiment of the present invention. In this case, the downhole tool assembly (18) is positioned above a whipstock (12) situated on a packer (28) and connected to upset tubing (14) which is also serves as a conduit to carry fluid (F), shown by arrows, from the pumping equipment (96) to the motor (40) that is attached to the flexible tubular shaft member (36) at an upper cross over member (128). Seals (41) positioned between the fluid motor (40) and the upset tubing (14) direct (shown by arrows) fluid (F) into the motor (40) which in turn causes the attached flexible tubular shaft member (36) and cutting head assembly (32) to rotate. As shown by arrows, the fluid (F) exits the cutting head assembly (32)

FIG. 10 illustrates a coiled tubing unit (97), air compressor (99) and cutting return tank (100) positioned on a wellbore (10) wherein the downhole tool assembly (18) is positioned in upset tubing (14) consistent with an embodiment of the present invention. Periodically, an air compressor (99) may be used to pump gas (G) down the upset tubing (14) and thru a lower passageway (3) below the whipstock (12) where it traverses a passageway (5) in a tubular member (4) and exits (6) so as to lift cuttings (C) out of the wellbore (10), as shown by arrows, where they may return to the cutting return tank (100).

As used herein, the term “hose” refers to elastomeric hose, single or multi-braided hose, sheathed hose, Kevlar® hose and comparable means of providing a means for fluid conduit.

As used herein, the terms “wire” or “cable” refers to wire and cable whether single or multi-stranded, wire rope and similar means for securing or providing tension between two ends.

As used herein, the term “fluid” refers to liquids, gases and/or any combination thereof.

Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc.

Depending on the context, all references herein to the “invention” may in some cases refer to certain specific embodiments only. In other cases it may refer to subject matter recited in one or more, but not necessarily all, of the claims. While the foregoing is directed to embodiments, versions and examples of the present invention, which are included to enable a person of ordinary skill in the art to make and use the inventions when the information in this patent is combined with available information and technology, the inventions are not limited to only these particular embodiments, versions and examples. Other and further embodiments, versions and examples of the invention may be devised without departing from the basic scope thereof and the scope thereof is determined by the claims that follow. 

What is claimed is:
 1. An apparatus for cutting laterally into an earthen formation from a wellbore comprising: a flexible tubular member formed from a series of interconnectable drive segments, wherein the interconnectable drive segments collectively form at least one tubular member inner passageway, the flexible tubular member being sized and configurable such that an attached cutting head assembly, the at least one tubular member inner passageway, and a fluid pumping source may be in fluid communication, and wherein a first flexible tubular member end portion is sized and configured to be attachable to a rotation means and a second flexible tubular member end portion operatively coupled to the cutting head assembly such that torque applied to the first flexible tubular member end portion by the rotational source may be translated to the cutting head assembly.
 2. The apparatus of claim 1 wherein the cutting head assembly comprises at least one cutting surface sized and configured to mechanically cut into the earthen formation.
 3. The apparatus of claim 1 wherein the cutting head assembly comprises a nozzle having at least one orifice for the ejection of fluid, gas or combination thereof positioned on or near the cutting head assembly and capable of being in fluid communication with the fluid pumping source.
 4. The apparatus of claim 1, further comprising sorts of flutes or grooves on the drive segments that can facilitate the removal of cuttings.
 5. The apparatus of claim 1, wherein the cutting head assembly further comprises a centering member sized and configured to retain the cutting head assembly substantially longitudinal about the axis of a substantially horizontal wellbore created by the apparatus when engaged in cutting laterally into the earthen formation and wherein the cuttings from the earthen formation may travel past the centralizing mechanism toward the wellbore.
 6. The apparatus of claim 1 further comprising one or more secondary tubular member disposed within the at least one flexible tubular member inner passageway and capable of providing a substantially leak-proof fluid conduit between the pumping source and the cutting head assembly.
 7. The apparatus of claim 6 further comprising flexible sealing material positioned between the interconnectable drive segments for the creation of a substantially leak-proof fluid passageway within the at least one flexible tubular member inner passageway so as to establish a fluid conduit between the pumping source and the cutting head assembly.
 8. The apparatus of claim 6, wherein the substantially leak-proof fluid conduit is created by selected from the group consisting of an elastomeric material, hose, braided-hose, flexible tubing, KEVLAR®, tubing, convoluted tubing, interlocking hose, semi-rigid tubing, and combinations thereof.
 9. The apparatus of claim 1 comprising two or more interconnectable drive segments each having a base plane situated generally perpendicular to an axis of rotation and having at least two male teeth generally positioned on at least one sides of the base plan and having at least two female sockets generally positioned on the opposing side of the base plane, such that the at least two male teeth on one side of the base plane of an interconnectable drive segment can mesh into at least two mating female sockets on an adjacent interconnectable drive segment thereby permitting the articulation and transference of torque of the flexible tubular shaft member around a radius.
 10. The apparatus of claim 9 comprising interconnectable drive segments having both male teeth and female sockets on each side of the base plane.
 11. The apparatus of claim 1 comprising two or more interconnectable drive segments having an outer profile that is generally cylindrical or barrel-shaped.
 12. The apparatus of claim 1 comprising two or more interconnectable drive segments having a base plane situated generally perpendicular to an axis of rotation and having at least one male drive tooth generally situated on one side of the base plan and at least one mating female socket on an opposing side wherein two or more lines bounding an edge of the male tooth do not meet at a single point on one side of the base plane, even if said lines bounding the edge(s) are extended.
 13. The apparatus of claim 3 being capable of emitting fluid from the at least one orifice on the nozzle providing at least one of the following benefits: keeping the cutting head clean, keeping the cutting head cool, emitting fluid to better dispose the formation to be cut, emitting chemicals for treating the formation, or emitting fluid to provide a medium for carrying formation cuttings back toward the wellbore.
 14. The apparatus of claim 1 wherein the flexible tubular member is deployed within a wellbore by means selected from the group consisting of production tubing, wireline, slickline unit, coiled tubing, and combinations thereof.
 15. The apparatus of claim 1 further comprising a rotational source selected from the group consisting of a fluid-driven motor, an electrical motor, or combinations thereof.
 16. The apparatus of claim 1 further comprising a tensioning means to hold the interconnectable drive segments together.
 17. The apparatus of claim 16, wherein the tensioning system is selected from the group comprising: the placement of an elastomeric material between the interconnectable drive segments so as to hold them in tension, the placement of a preload on a hose running through an inner tubular passageway of the flexible tubular shaft member, the placement of a preload on a cable(s) running through an inner passageway of the flexible tubular shaft member, the incorporation of a spring situated above the interconnectable drive segments wherein the spring pushes the interconnectable drive segments together, directly, pulls the interconnectable drive segments together by pulling tension on a hose, wire or cable(s) running through an inner passageway of the interconnectable drive segments, and combinations thereof.
 18. The apparatus of claim 1 further comprising a whipstock to guide the interconnectable drive segments.
 19. The apparatus of claim 18, wherein the whipstock comprises a passageway through which formation cuttings can pass from the cutting head assembly to a location below the whipstock.
 20. The apparatus of claim 1 further comprising a sealing apparatus used in conjunction with a wireline unit allowing fluid communication with surface pumping equipment, said sealing apparatus providing a sealing mechanism between a fluid motor and a tubular extending to the surface through which fluid can be pumped, said sealing mechanism diverting flow from the surface pumping equipment through said tubular and into the fluid motor causing rotation of the motor and attached interconnectable drive segments and ultimately cutting head assembly, said motor connected to a wireline whereby the flexible tubular member may be lowered so as to create a lateral borehole in the earthen formation.
 21. A method for cutting laterally into an earthen formation from a wellbore comprising: guiding a downhole tool assembly comprising a series of interconnectable drive segments, defining at least one inner passageway, through a channel defined by a guide assembly and positioning the downhole tool assembly so that the downhole tool assembly contacts a portion of the earthen formation to be laterally cut, wherein the downhole tool assembly is coupled to a conduit, such that the conduit and downhole tool assembly are in fluid communication; pumping one or more fluids through the conduit and into the downhole tool assembly; rotating a cutting head of the downhole assembly; and cutting a borehole into the earthen formation with the cutting head in a direction lateral to the wellbore.
 22. The method of claim 21, wherein the downhole tool assembly is operatively connected to a rotational source and the rotational source is coupled to a conduit, such that the conduit, rotational source, and downhole tool assembly are in fluid communication; activating the rotational source, wherein a torque is applied to the interconnected drive segments forming a flexible tubular member; and translating the torque to a cutting head of the downhole tool assembly, wherein the torque causes the cutting head to rotate.
 23. The method of claim 22, wherein the rotational source is activated by the fluid flow through the conduit into the rotational source.
 24. The method of claim 21, wherein the interconnected drive segments collectively define a tubular member inner passageway, and the downhole tool assembly further comprises a nozzle defining one or more openings in fluid communication with at least a portion of a secondary tubular member disposed within the tubular member fluid passageway, wherein the method further comprises pumping one or more fluids through the secondary tubular member; and emitting the pumped fluid from the nozzle openings, whereby the fluid contacts the cutting head.
 25. The method of claim 24, wherein the nozzle openings comprise one or more orifices selected from the group consisting of a nozzle orifice at the center of the cutting head, a nozzle orifice(s) that are situated about the radius of the axis of rotation of the nozzle head, a rotating nozzle, a pulsing nozzle, a nozzle that creates a swirling pattern in its discharge flow, a nozzle designed to produce cavitation, and combinations thereof.
 26. The method of claim 21, wherein fluid is pumped through a fluid motor so as to rotate the flexible tubular member and the cutting head so as to cut earthen formation.
 27. The method of claim 21, further comprising forming a lateral borehole through a pre-existing hole created thru the casing; said hole created by one or more of the following methods: milling out the section of casing, abrasively cutting the casing, punching through the casing, cutting a hole in the casing, or using chemical to erode the wellbore casing.
 28. The method of claim 21, further comprising forming a hole through a wellbore casing and further lowering said tools under rotation so as to cut through any adjacent cement and into the earthen formation.
 29. The method of claim 21, further comprising pumping fluid to a location beneath the downhole tool assembly and at a sufficient velocity so as either suspend formation cuttings within the wellbore or to lift the cuttings to the surface.
 30. The method of claim 21, further comprising a means to vibrate at least a portion of the downhole assembly so as to mitigate the cutting head and/or flexible tubular member assembly from becoming stuck in the borehole.
 31. The method of claim 21, wherein the wellbore is an open hole wellbore and a borehole is formed into the earthen formation in a direction lateral to the open hole wellbore. 